Note: Descriptions are shown in the official language in which they were submitted.
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CONTROLLED HYDROSTATIC PRESSURE COMPLETION SYSTEM
TECHNICAL FIELD
The present disclosure relates generally to equipment
utilized and operations performed in conjunction with a
subterranean well and, in an embodiment described herein,
more particularly provides a controlled hydrostatic pressure
completion system.
BACKGROUND
To prevent damage to a reservoir penetrated by a
wellbore, to prevent unacceptable fluid loss to the
reservoir, and to prevent excessive fluid influx from the
reservoir, techniques have been developed to accurately
control wellbore pressures. For example, in managed
pressure drilling or optimized pressure drilling, the
wellbore can be closed off from the atmosphere to enable
closed-loop control of wellbore pressures via regulation of
rig pump pressure, return flow through a choke manifold, a
dual density fluid column, etc.
Therefore it will be appreciated that it would be
beneficial to provide for a controlled hydrostatic pressure
completion system.
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BRIEF DESCRIPTION OF THE DRAWINGS
FIG. 1 is a representative partially cross-sectional
view of a well system and associated method which can embody
principles of the present disclosure.
FIGS. 2-9 are representative illustrations of a
sequence of steps in the method.
FIGS. 10-12 are representative illustrations of an
alternate sequence of steps in the method.
DETAILED DESCRIPTION
Representatively illustrated in FIG. 1 is a well system
10 and associated method which can embody principles of the
present disclosure. In the method, a wellbore 12 is drilled
into an earth formation 14 comprising a reservoir, for
example, of hydrocarbon fluid. In other examples, the well
system 10 could comprise a geothermal well, an injection
well, or another type of well. Thus, it should be
understood that it is not necessary for the well to be used
for production of hydrocarbon fluid.
The wellbore 12 is drilled by rotating a drill bit 16
on a downhole end of a generally tubular drill string 18.
Drilling fluid 20 is circulated through the drill string 18
and an annulus 22 surrounding the drill string during the
drilling operation.
In the FIG. 1 example, the drill string 18 extends
through a wellhead 24, a blowout preventer stack 26 and a
rotating control device 28 at a surface location 30. The
rotating control device 28 (also known as a rotating blowout
preventer, a rotating control head, a rotating diverter,
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etc.) seals off the annulus 22 about the drill string 18
while the drill string rotates. In other examples, the
drill string 18 may not rotate during drilling (such as,
examples in which a drilling motor is used to rotate the
drill bit 16).
The surface location 30 could be at a land-based
drilling rig, an offshore drilling rig, a jack-up drilling
rig, a subsea mud line, etc. For the purposes of this
disclose, the earth's surface, whether or not covered by
water, is considered a surface location.
During drilling, an open hole (uncased) section of the
wellbore 12 is exposed to hydrostatic pressure in the
wellbore due to a weight of the drilling fluid 20, fluid
friction due to flow of the fluid through the annulus 22,
pressure applied by a rig pump 32, and backpressure due to
restriction to flow of the drilling fluid through a choke
manifold 34. These influences on the pressure in the
wellbore 12 can be controlled using techniques known to
those skilled in the art as managed, optimized,
underbalanced, at balance, etc., drilling.
A fluid conditioning facility 40 can separate gas and
solids from the drilling fluid 20, and otherwise condition
the fluid as it is circulated from the choke manifold 34 to
the rig pump 32. In this example, the fluid conditioning
facility 40 comprises the rig's mud system, e.g., including
a degasser, shale shakers, mud tanks, mixing tanks, etc.
The density of the drilling fluid 20 can be varied as needed
in the facility 40, to thereby change the hydrostatic
pressure exerted by the drilling fluid in the wellbore 12.
If desired, pressure can be added to the drilling fluid
20 by means of a backpressure or makeup pump 36, fluid can
be diverted from the drill string 18 to the choke manifold
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34 during cessation of drilling fluid flow through the drill
string (such as, while making connections in the drill
string, etc.), and the hydrostatic pressure of the drilling
fluid can be decreased by adding a relatively low density
fluid 38 (such as nitrogen gas, gas-filled glass spheres,
etc.) to the drilling fluid before or after the drilling
fluid is pumped through the drill string 18.
By uging these techniques and others, pressure in the
wellbore 12 section directly exposed to the formation 14 can
be maintained greater than, equal to, and/or less than pore
pressure of the formation in that section of the wellbore.
In different circumstances, it may be desired to drill into
the formation 14 while pressure in the exposed section of
the wellbore 12 is maintained overbalanced, underbalanced or
balanced with respect to pore pressure in the formation.
Referring additionally now to FIGS. 2-9, a series of
steps in a method 44 of drilling and completing the wellbore
12 are representatively illustrated. The method 44 can be
practiced with the well system 10 depicted in FIG. 1, but
its practice is not limited to the FIG. 1 well system.
FIG. 2 illustrates that, in this example, the wellbore
12 has been drilled and cased to a depth approaching a
desired open hole completion location. As depicted in FIG.
2, several casing strings 46 have been installed and
cemented, with a lowermost one of these being a production
casing. FIG. 2 also illustrates that, in this example, the
wellbore 12 can contain a fluid column 56.
In FIG. 3, the drill string 18 is used to extend the
wellbore 12 into the formation 14. A liner string 42 has
the drill bit 16 connected below a perforated shroud 48 and
an expandable liner hanger 50. The drill string 18 is
releasably connected to the expandable liner hanger 50 with
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a service tool 54. The perforated shroud 48 is connected
between the hanger 50 and the drill bit 16. The fluid
column 56 surrounds the liner string 42 and drill bit 16.
A suitable perforated shroud for use as the shroud 48
is the CAPS(TM) shroud marketed by Halliburton Energy
Services, Inc. of Houston, Texas USA. The shroud 48 could
be another type of perforated liner in other examples. As
used herein, the term "perforated shroud" includes
perforated liners, slotted liners, well screen shrouds and
similar equipment.
As the drill string 18 rotates, the drill bit 16,
shroud 48 and liner hanger 50 also rotate, and the drill bit
penetrates the formation 14. Alternatively, or in addition,
the drill bit 16 (but not the shroud 48 and liner hanger 50)
may be rotated by use of a conventional mud motor (not
shown) interconnected in the drill string 18 above the drill
bit. Eventually, a desired total depth of the wellbore 12
is reached.
In FIG. 4, the liner hanger 50 has been set in the
production casing string 46, thereby securing the shroud 48
in the section of the wellbore 12 directly exposed to the
formation 14. The hanger 50 is preferably set by expanding
it outward into gripping and sealing contact with the casing
string 46. A VERSAFLEX(TM) expandable liner hanger marketed
by Halliburton Energy Services, Inc. is expanded by driving
a conical wedge through a tubular mandrel to outwardly
deform the mandrel, but other types of liner hangers or
packers, and other ways of expanding hangers, may be used in
other examples.
Note that a plug 52 is set in the liner string 42,
preferably using the drill string 18 as it is being
withdrawn from the wellbore 12. The plug 52 can be latched
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into a suitable profile in the liner string 42, can be set
by application of pressure, force, etc., or otherwise
sealingly engaged in the liner string. This plug 52
isolates the section of the wellbore 12 directly exposed to
the formation 14 from hydrostatic pressure due to the fluid
column 56 vertically above that section of the wellbore.
Note, also, that the wellbore 12 in this example has
been drilled into the formation 14, the shroud 48 has been
positioned in the open hole section of the wellbore, the
liner string 42 has been secured by setting the hanger 50,
and the plug 52 has been set in the liner string, without
exposing the formation to hydrostatic pressure of a full
liquid column, and in only a single trip of the drill string
18 into the wellbore.
The formation 14 is not exposed to hydrostatic pressure
of a full liquid column, because while the wellbore 12 is
being drilled with the liner string 42, two-phase drilling
fluid 20 is circulated through the drill string 18 (e.g.,
with low density fluid, such as nitrogen gas, being added to
the drilling fluid), so that the drilling fluid comprises
both liquid and gas. After the plug 52 is set (e.g., by
latching the plug into a suitable profile in the liner
string 42), the fluid column 56 might comprise a full liquid
column extending to the surface location 30, but the plug
will isolate that liquid column from the formation 14.
Separate trips of the drill string 18 into the wellbore
12 are not needed to separately drill the wellbore into the
formation 14, run the liner string 42 and set the liner
hanger 50, set the plug 52, etc. Wellbore pressure control
is simplified, and less time and expense are required, if
the number of trips into the wellbore 12 can be minimized.
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In FIG. 5, an injection liner 58 is installed in the
production casing string 46. This permits a gas 60 (such as
nitrogen) to be injected into the wellbore 12 via an annular
space 62 formed radially between the injection liner 58 and
the production casing string 46. If dimensions permit, the
injection liner 58 can be installed prior to drilling the
open hole section of the wellbore 12.
The gas 60 reduces the density of the fluid column 56,
thereby providing a means of controlling hydrostatic
pressure in the wellbore 12. More or less gas 60 can be
flowed via the annular space 62 to respectively decrease or
increase the hydrostatic pressure exerted by the fluid
column 56.
In FIG. 6, a sand control assembly 64 is installed in
the wellbore 12. In this example, the sand control assembly
64 includes a plug release tool 66 which can engage and
release the plug 52 to then allow the open hole section of
the wellbore 12 to be exposed again to the fluid column 56
above the liner string 42.
As depicted in FIG. 7, the sand control assembly 64 is
fully installed. In this example, the sand control assembly
64 includes a well screen 68, an isolation valve 70, a
crossover 72 and a gravel pack packer 74. These components
are well known to those skilled in the art, and so are not
further described herein.
A suitable valve for use as the isolation valve 70 is
the FS-2 Fluid Loss Device marketed by Halliburton Energy
Services, Inc. A suitable packer for use as the gravel pack
packer is the VERSA-TRIEVE(TM), also marketed by Halliburton
Energy Services, Inc. However, other types of isolation
valves, fluid loss control devices and packers may be used
in keeping with the principles of this disclosure.
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The sand control assembly 64 is conveyed into the
wellbore 12 by a work string 76. The packer 74 is set in
the liner string 42, thereby securing and sealing the sand
control assembly 64 in the liner string.
The open hole section of the wellbore 12 can optionally
be gravel packed by flowing a gravel slurry through the work
string 76, and outward via the crossover 72 into the annulus
22. However, it is not necessary to gravel pack the open
hole section of the wellbore 12 in keeping with the
principles of this disclosure.
If the wellbore 12 is gravel packed, gravel 78 (not
shown in FIG. 7, see FIGS. 8 & 9) will accumulate about the
well screen 68, and both inside and outside the shroud 48.
The fluid portion of the gravel slurry flows into the screen
68, upward through the crossover 72 and into the annulus 22
above the packer 74. The fluid portion is lightened by
nitrogen gas 60 (or another fluid less dense as compared to
the fluid portion) flowed into the fluid column 56 via an
annulus formed radially between the injection liner 58 and
the casing string 46. This prevents the formation 14 from
being exposed to a full liquid column hydrostatic pressure
throughout the gravel packing procedure. Of course, the
wellbore 12 could be gravel packed using other techniques,
if desired.
The work string 76 is then retrieved from the well. As
the work string 76 is withdrawn from the sand control
assembly 64, the isolation valve 70 is closed, thereby again
isolating the now gravel packed section of the wellbore 12
while the injection liner 58 is retrieved from the well and
an upper completion string 80 is installed. During this
process, a filter cake treatment may be applied, if desired.
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In FIG. 8, the completion string 80 is being installed
while the isolation valve 70 remains closed. In FIG. 9, the
completion string 80 is fully installed, the isolation valve
70 is opened (e.g., in response to engagement between the
completion string and the sand control assembly 64,
application of a predetermined series of pressure
manipulations, etc.), and the system is ready for production
of fluid from the formation 14.
FIGS. 10-12 depict an alternate series of steps in the
method 44. The steps of FIGS. 10-12 can be substituted for
the steps of FIGS. 3-5. Instead of drilling into the
formation 14 with the liner string 42 connected at an end of
the drill string 18, the steps of FIGS. 10-12 begin with the
wellbore 12 being drilled into the formation 14 without the
liner string.
In FIG. 10, the wellbore 12 has been drilled with the
drill bit 16 on the end of the drill string 18 (as depicted
in FIG. 1), but without the liner string 42. Thus, there is
no liner string 42 in the open hole section of the wellbore
12 when it is drilled.
In FIG. 11, a plug 82 is set in the production casing
string 46 after the open hole section of the wellbore 12 has
been drilled. The plug 82 isolates the open hole section of
the wellbore 12 from the fluid column 56 vertically above
the plug.
In FIG. 12, the plug 82 has been drilled through or
otherwise removed, and the liner string 42 is installed in
the open hole section of the wellbore 12. The plug 82 can
be drilled through, released, unset, etc., by the liner
string 42 when it is installed.
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This alternate version of the method 44 now proceeds to
the step depicted in FIG. 6, wherein the sand control
assembly 64 is installed in the liner string 42.
Although specific examples of equipment, components,
elements, etc. of the well system 10 are described above,
and specific steps and techniques are described above for
certain examples of the method 44, it should be clearly
understood that this disclosure is not limited to only these
specific examples. Many variations of well systems and
methods may be practiced using the principles of this
disclosure.
In one example, this disclosure describes a method 44
of drilling and completing a well. The method 44 can
include performing the following steps a) - d) in a single
trip of a drill string 18 into a wellbore 12:
a) drilling a section of the wellbore 12;
b) positioning a perforated shroud 48 in the
section of the wellbore 12;
C) securing the perforated shroud 48 by setting a
hanger 50; and
d) isolating the section of the wellbore 12 from a
remainder of the wellbore 12 vertically above the section of
the wellbore 12.
Steps a) - d) are preferably performed while the
= 25 section of the wellbore 12 is not exposed to a liquid column
extending to a surface location 30.
Steps a) - d) can be performed while the section of the
wellbore 12 is exposed to a two-phase fluid column 56.
Setting the hanger 50 can include expanding the hanger
50.
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Isolating the section of the wellbore 12 can involve
setting a plug 52 in a liner string 42 which includes the
hanger 50 and the perforated shroud 48.
The method 44 may include gravel packing the section of
the wellbore 12. The gravel packing step can include
unsetting the plug 52, positioning a sand control assembly
64 in the liner string 42, and flowing a gravel 78 slurry
into an annulus 22 between the sand control assembly 64 and
the section of the wellbore 12. The gravel packing can be
performed in a single trip of a work string 76 into the
wellbore 12.
The method 44 can include installing an injection liner
58 in a casing string 46, and flowing a gas 60 into the
casing string 46 through an annular space 62 between the
injection liner 58 and the casing string 46. Installing the
injection liner 58 can be performed after isolating the open
hole section of the wellbore 12 and prior to gravel packing
the open hole section of the wellbore 12. Installing the
injection liner 58 can be performed prior to drilling the
open hole section of the wellbore 12.
Drilling the open hole section of the wellbore 12 can
include rotating a drill bit 16 connected to the perforated
shroud 48.
A method 44 of drilling and completing a well can
include: drilling a section of a wellbore 12; positioning a
perforated shroud 48 in the section of the wellbore 12;
securing the perforated shroud 48 by setting a hanger 50;
and isolating the section of the wellbore 12 from a
remainder of the wellbore 12 vertically above the section of
the wellbore 12. The drilling, positioning, securing and
isolating steps are performed while the section of the
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wellbore 12 is not exposed to a liquid column extending to
a surface location 30.
It is to be understood that the various embodiments
of the present disclosure described herein may be utilized
in various orientations, such as inclined, inverted,
horizontal, vertical, etc., and in various configurations,
without departing from the principles of the present
disclosure. The embodiments are described merely as
examples of useful applications of the principles of the
disclosure, which is not limited to any specific details
of these embodiments.
In the above description of the representative
embodiments of the disclosure, directional terms, such as
"above," "below," "upper," "lower," etc., are used for
convenience in referring to the accompanying drawings. In
general, "above," "upper," "upward" and similar terms
refer to a direction toward the earth's surface along a
wellbore, and "below," "lower," "downward" and similar
terms refer to a direction away from the earth's surface
along the wellbore.
Of course, a person skilled in the art would, upon a
careful consideration of the above description of
representative embodiments of the disclosure, readily
appreciate that many modifications, additions,
substitutions, deletions, and other changes may be made to
the specific embodiments, and such changes are
contemplated by the principles of the present disclosure.
Accordingly, the foregoing detailed description is to be
clearly understood as being given by way of illustration
and example only, the scope of the present invention being
limited solely by the appended claims and their
equivalents.
